Gas lift system

ABSTRACT

An improved gas lift system is provided. In certain embodiments, the gas lift system includes a first tubing string and a second tubing string disposed within the first tubing string. The second tubing string is movable between a first position and a second position. Inflow of production fluids through an aperture in the first tubing string is selectively blocked when the second tubing string is in the second position. A port in the second tubing string delivers lift gas to the annulus between the first tubing string and the second tubing string. In the first position, the port is blocked to prevent fluid communication between the second tubing string and the first tubing string. In the second position, the port is uncovered to permit fluid communication between the second tubing string and the first tubing string, while a sealing member provides a seal that isolates the fluid communication from a well formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.61/036,451, filed Mar. 13, 2008, which is hereby incorporated byreference.

BACKGROUND

1. Field of the Invention

The invention relates generally to the recovery of subterranean depositsand more specifically to systems and methods for controlling andremoving fluids in a well.

2. Description of Related Art

Oil and gas wells frequently require artificial lift processes to removeliquids from the wells. Gas lift systems are a type of artificial liftthat typically operate by injecting pressurized gas near the base of theaccumulated fluid level to force the liquid to the surface. Problems canoccur, however, if gas lift operations are used in horizontal wells orin wells with low-pressure formations. In these instances, the injectedgas can flow downhole or into the producing formation, either of whichcauses inefficient use of the lift gas and further impedes oil and/orgas production.

SUMMARY

The problems presented in removing liquid from a gas-producing well aresolved by the systems and methods of the illustrative embodimentsillustrated herein. In one embodiment, a gas lift system for removingliquid from a wellbore includes a first tubing string positioned withinthe wellbore and a second tubing string disposed within the first tubingstring. The second tubing string is movable between a first position anda second position, and an annulus is present between the second tubingstring and the first tubing string. An aperture is positioned in thefirst tubing string. A sleeve is slidingly disposed around a portion ofthe second tubing string, and a port is disposed in a wall of the secondtubing string. The port is substantially covered by the sleeve in thefirst position and is substantially uncovered in the second position topermit fluid communication between an inner passage of the second tubingstring and the annulus. A sealing member is operatively associated withthe aperture to allow fluid communication between the wellbore and theannulus when the second tubing string is in the first position. Thesealing member substantially inhibits fluid communication through theaperture when the second tubing string is in the second position.

In another embodiment, a gas lift system for removing liquid from awellbore includes a first tubing positioned within the wellbore and asecond tubing string disposed within the first tubing string. The firsttubing string is fluidly connected to a separator, and the second tubingstring is operatively connected to a lifting device to move the secondtubing string between a first position and a second position. The secondtubing string includes an inner passage fluidly connected to an outletof a compressor. An aperture is positioned near an end of the firsttubing string, the aperture being adapted to receive an end of thesecond tubing string in the second position. A first flange is disposedon the second tubing string, and a second flange is disposed on thesecond tubing string. A sleeve is slidingly disposed around the secondtubing string between the first flange and the second flange within thefirst tubing string. An outlet is disposed in a wall of the secondtubing string such that the outlet is closed by the sleeve in the firstposition and is open in the second position to permit fluidcommunication between the inner passage of the second tubing string anda first annulus between the first tubing string and the second tubingstring. A sealing member is provided to create a seal between theaperture in the first tubing string and the end of the second tubingstring in the second position.

In still another embodiment, a gas lift system for removing liquid froma wellbore is provided and includes a first tubing string positionedwithin the wellbore and a second tubing string disposed within the firsttubing string. The second tubing string is rotatable between a firstposition and a second position. An aperture in the first tubing stringis adapted to receive an end of the second tubing string in the secondposition. A sealing member is provided for creating a seal between theaperture in the first tubing string and the end of the second tubingstring in the second position. A first port is positioned on the secondtubing string in fluid communication with a first inner passage of thesecond tubing string. A second port is positioned on the second tubingstring in fluid communication with the first inner passage of the secondtubing string. The first and second ports are disposed on opposite sidesof the sealed aperture and are substantially open when the second tubingstring is positioned in the first position. At least one of the firstand second ports is substantially blocked when the second tubing stringis in the second position. A third port is positioned on the secondtubing string in fluid communication with a second inner passage of thesecond tubing string. The third port is substantially blocked when thesecond tubing string is in the first position and is substantially openwhen the second tubing string is in the second position.

In yet another embodiment, a gas lift system for removing liquid from awellbore includes a first tubing string positioned within the wellboreand a second tubing string disposed within the first tubing string. Thesecond tubing string includes an inner passage and is movable between afirst position and a second position. An annulus is present between thesecond tubing string and the first tubing string. An aperture isdisposed in the first tubing string to permit fluid communicationbetween the wellbore and the annulus when the second tubing string is inthe first position. A port is disposed in the second tubing string topermit fluid communication between the inner passage and the annuluswhen the second tubing string is in the second position.

In another embodiment, a gas lift system for removing liquid from awellbore includes a first tubing string positioned with the wellbore anda second tubing string disposed within the first tubing string. Thesecond tubing string is movable between a first position and a secondposition. The system further includes a downhole valve actuated bymovement of the second tubing string to allow a lift gas to flow fromone of the first and second tubing strings to another of the first andsecond tubing strings.

In still another embodiment, a gas lift system for removing liquid froma wellbore is provided and includes a first tubing string positionedwith the wellbore and a second tubing string disposed within the firsttubing string. The second tubing string is movable between a firstposition and a second position. The system further includes a downholevalve actuated by movement of the second tubing string to isolate thefirst and second tubing strings from the wellbore during operation of agas lift process.

In yet another embodiment, a gas lift system for removing liquid from awellbore includes a first tubing string positioned in a wellbore andhaving a selectively closable downhole end. A second tubing string ispositioned within the first tubing string, and the second tubing stringis fluidly connected to a source of pressurized gas. A sleeve isdisposed around the second tubing string and is movable relative to thesecond tubing string to selectively open or close an outlet of thesecond tubing string.

In another embodiment, a method for removing liquid from a wellbore of awell includes positioning a first tubing string in the wellbore andpositioning a second tubing string within the first tubing string. Thesecond tubing string is moved into a removal position to (1) isolate anannulus between the first tubing string and the second tubing stringfrom a formation of the well, and (2) inject gas from the second tubingstring into the annulus. The second tubing string is moved into aproduction position to allow production of production fluid from theformation through the annulus.

Other objects, features, and advantages of the invention will becomeapparent with reference to the drawings, detailed description, andclaims that follow.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a front schematic view of a gas lift system accordingto an illustrative embodiment;

FIG. 2 depicts a front schematic view of a valve mechanism that may beused with the gas lift system of FIG. 1 according to an illustrativeembodiment, the valve mechanism including a second tubing stringpositioned in a retracted position;

FIG. 3 illustrates the valve mechanism of FIG. 2 with the second tubingstring in an extended position;

FIG. 4 depicts a sleeve of the valve mechanism of FIGS. 2 and 3;

FIG. 5 illustrates a front schematic view of a downhole valve that maybe used with the gas lift system of FIG. 1 according to an illustrativeembodiment, the downhole valve having a second tubing string rotatablewithin a first tubing string to selectively operate the downhole valve;

FIG. 6 depicts a cross-sectional side view of a portion of the downholevalve of FIG. 5 taken at 6-6;

FIG. 7 illustrates a cross-sectional side view of a portion of thedownhole valve of FIG. 5 taken at 7-7;

FIG. 8 depicts a cross-sectional side view of a portion of the downholevalve of FIG. 5 taken at 8-8;

FIG. 9 illustrates a front view of a downhole valve that may be usedwith the gas lift system of FIG. 1 according to an illustrativeembodiment, the downhole valve having a second tubing string positionedwithin a first position;

FIG. 10 depicts a front view of the downhole valve of FIG. 9 with thesecond tubing string positioned within a second position;

FIG. 11 illustrates a cross-sectional side view of a portion of thedownhole valve of FIG. 9 taken at 11-11; and

FIG. 12 depicts a cross-sectional side view of a portion of the downholevalve of FIG. 9 taken at 12-12.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

In the following detailed description of the illustrative embodiments,reference is made to the accompanying drawings that form a part hereof,and in which is shown by way of illustration specific embodiments inwhich the invention may be practiced. These embodiments are described insufficient detail to enable those skilled in the art to practice theinvention, and it is understood that other embodiments may be utilizedand that logical structural, mechanical, electrical, and chemicalchanges may be made without departing from the spirit or scope of theinvention. To avoid detail not necessary to enable those skilled in theart to practice the invention, the description may omit certaininformation known to those skilled in the art. The following detaileddescription is, therefore, not to be taken in a limiting sense, and thescope of the illustrative embodiments is defined only by the appendedclaims.

Referring to FIG. 1, an improved gas lift system 306 according to anillustrative embodiment is used in a well 308 that may have at least onesubstantially horizontal portion for producing gas, coalbed methane,oil, or other subterranean deposits from a formation 309. The gas liftsystem 306 includes a first tubing string 310 disposed within a wellbore312 of the well 308 that extends from a surface 313 of the well 308 to adownhole location within the wellbore 312. At or near the surface 313,the first tubing string 310 is fluidly connected to a separator 314,which is in turn fluidly connected to an inlet 315 of the compressor316. The first tubing string 310 acts as a fluid conduit for fluidremoved from the wellbore 312. Since the fluid is removed through a gaslift operation, as described in more detail below, the removal processdelivers a mixture of gas and liquid to the separator 314, whichseparates the liquid from the gas. The gas may be returned to thecompressor 316, which is used to drive the gas lift operation. Althougha compressor is described as receiving low pressure gas from the welland boosting the pressure so as to provide high pressure discharge gasused in the gas lift process, other configurations are also envisioned.For example, gas may flow directly from the wellbore 312 to a sales line398 without the use of a dedicated compressor 316. In such a case, aseparate high pressure source would provide the necessary lift gas. Insuch a case, a separate high pressure source would provide the necessarylift gas. Similarly, if the well produces little gas, such as might bethe case in an oil well, off-site lift gas may be piped to the well.Alternatively, compressed air may be used as the lift-gas, eliminatingany value of capture and re-use of such lift gas.

A second tubing string 320 is positioned within the first tubing string310 and extends downhole from the surface 313 of the well 308. Thesecond tubing string 320 is fluidly connected to an outlet 324 of thecompressor 316 and may remain constantly charged with dischargepressure. Optionally, a valve 328 may be positioned between the outlet324 and the second tubing string 320 to selectively control introductionof compressed gas to the second tubing string 320 during gas liftoperations. During gas lift operations, gas from the compressor 316flows through second tubing string 320 to lift accumulated liquids fromthe well through the annulus between the first tubing string 310 and thesecond tubing string 320. Although not expressly described, it is wellunderstood that gas lift processes are flexible with respect toinjection and discharge conduits. As such, lift gas could be injectedthrough the annulus of first tubing string 310 and second tubing string320, and produced liquids could return up the second tubing string 320.

An annulus 332 is present between the first tubing string 310 and thewellbore 312 through which gas may be produced during certainoperational modes of the well 308, which are described in more detailbelow. The annulus 332 is fluidly connected at or near the surface 313to the inlet 315 of the compressor 316. As previously described, thefirst tubing string 310 is also fluidly connected (through the separator314) to the inlet 315 of the compressor 316. A three-way connector 333is provided to fluidly connect both the first tubing string 310 and theannulus 332 to the inlet 315. A valve 336 is positioned between theannulus 332 and the compressor inlet 315 to selectively allow or preventfluid flow depending on the operational mode of the well. A check valve340 is also provided to prevent flow of fluids from the first tubingstring 310 into the annulus 332.

Referring to FIGS. 2 and 3, the second tubing string 320 preferablyterminates in a sealed, downhole end 334. The first tubing string 310may include an end cap 338 with an aperture 342 passing through the endcap 338. The aperture 342 is adapted to receive the downhole end 334 ofthe second tubing string 320, and sealing members 348 such as o-ringsare positioned within the aperture 342 or on the sealed end 334 tocreate a sealing engagement between the end cap 338 and the secondtubing string 320.

A first flange 356 and a second flange 358 are disposed on the secondtubing string 320 uphole of the end cap, and a shoulder 360 is disposedon an inner wall of the first tubing string 310. An aperture orplurality of apertures, or ports 364 communicate with an inner passage368 of the second tubing string 320 to deliver lift gas from thecompressor 316, through the second tubing string 320 to an annulus 372between the first tubing string 310 and the second tubing string 320.

Referring still to FIGS. 2 and 3, but also to FIG. 4, a sleeve 611 isslidingly disposed on the second tubing string 320 between the firstflange 356 and the second flange 358, thus forming a sliding valvemechanism that exposes or covers the plurality of ports 364 on thesecond tubing string 320. In one embodiment, the sleeve 611 may bemovable within the first tubing string 310, while in another embodimentthe sleeve 611 may be rigidly fixed to the first tubing string 310. Thesleeve 611 includes a substantially cylindrical central portion 615 anda plurality of extension portions 619 extending radially outward from anouter surface of the central portion 615. The extension portions 619serve to centralize the second tubing, while providing a flow path tofluids traveling past the sleeve 611. The central portion 615 of thesleeve includes a passage 625 that receives the second tubing string320. In one embodiment, the sleeve 611 is integrally formed from asingle piece of material, although the components of the sleeve 611could be individually fabricated and then welded, joined, bonded, orotherwise attached.

In certain embodiments, a spring member 631 is operatively engaged withthe second tubing string 320. In one embodiment, the spring member 631is positioned between the sleeve 611 and the first flange 356 to biasthe sleeve 611 toward the second flange 358 when the spring member 631is in an uncompressed position (see FIG. 2). The spring member 631 iscapable of being in the uncompressed position when the second tubingstring 320 has been retracted into a retracted, or production position(see FIG. 2). In the retracted position, the downhole end 334 of thesecond tubing string 320 is disengaged from the aperture 342 of the endcap 338, which results in free passage of fluids between the annulus 372and the wellbore 312. When the spring is in the uncompressed position,the passage 625 of the sleeve 611 covers the plurality of ports 364 onthe second tubing string 320. Sealing members such as elastomerico-rings (not shown) positioned within the passage 625 or disposed on thesecond tubing string 320 adjacent the ports 364 provide a sealingconnection between the sleeve 611 and the second tubing string 320 thuspreventing exhaust of gas from the second tubing string 320 into theannulus 372. Alternatively, the sleeve 611 may itself be formed ofelastomeric material with an interference fit between second tubingstring 320 so as to provide the necessary sealing connection.

In the embodiment described above, the spring member 631 may be placedin a compressed position (see FIG. 3) by extending the second tubingstring 320 into an extended, or removal position (see FIG. 3). As thesecond tubing string 320 moves into the extended position, the sleeve611 abuts the shoulder 360 of the first tubing string 310 which causesthe spring member 631 to compress as the second tubing string 320continues to extend. In the extended position illustrated in FIG. 3, thespring member 631 is substantially compressed, and the sleeve 631 hastraveled uphole relative to the second tubing string 320, which permitspressurized gas within the second tubing string 320 to exhaust into theannulus 372. Additionally, in the extended position, the downhole end334 of the second tubing string 320 may fully engage the aperture 342 ofthe end cap 338, which results in sealing engagement between the end cap338 and the second tubing string 320. This sealing engagement preventspressurized gas in the annulus 372 from exhausting through the aperture342, thus forming an isolated chamber for gas lifting the liquids to thesurface. In one embodiment, a fully extended position is reached whenthe second flange 358 of the second tubing string 320 abuts the end cap338. In another embodiment, a fully extended position may be reachedwhen the sleeve 631 abuts the shoulder 360 and the spring member 631becomes fully compressed.

Together, the first tubing string 310, the second tubing string 320, andthe sleeve 611 act as a downhole valve 380 that selectively controls twofluid flow paths based on axial movements of the second tubing string320.

Referring again to FIG. 1, but still to FIGS. 2-4, a lifting device 392is provided at or near the surface 313 and is cooperative with thesecond tubing string 320 to lift and lower the second tubing string 320.Lifting of the second tubing string 320 moves the second tubing stringinto the retracted position. Lowering of the second tubing string 320moves the second tubing string into the extended position. In apreferred embodiment, the lifting device 392 at the wellhead would usethe lift gas as a source of motive pressure. Alternatively, the liftingdevice 392 may be hydraulically, pneumatically, mechanically, orelectrically driven. The lifting device may also be placed down-hole ofthe surface wellhead assembly.

In the illustrative embodiments described herein, the gas lift system306 allows a gas-lift, fluid-removal operation in which the point of gasinjection (i.e. ports 364) is positively isolated and blocked fromcommunication with the well formation 309. This positive sealing processis especially advantageous in horizontal wells, where an alternativeisolation device, such as a gravity operated check valve, may notperform adequately. Additionally, because the point of gas liftinjection is selectively isolated within a separate tubing string (i.e.first tubing string 310), normal production of the formation 309 maycontinue uninterrupted during the gas-lift, fluid removal operation.

In operation, the well 308 may be operated in one of at least two modes:a “normal production” mode and a “blow down” mode. In the normalproduction mode, the second tubing string 320 is lifted by the liftingdevice 392 into the retracted position. Additionally, the valve 336 ispositioned in a closed position to prevent fluid flow to compressor 316through annulus 332. Since the retracted positioning of the secondtubing string 320 (i) unseals the end cap 338 and (ii) preventspressurized gas from the second tubing string from entering the annulus372, normal production of gas from the formation 309 is allowed toproceed through the annulus 372 into the separator 314 and into thecompressor 316. At the compressor 316, the gas may be pressurized fordelivery to a production conduit 398 for sale of the gas. A portion ofthe gas exiting the compressor 316 may also be diverted to charge thesecond tubing string 320 for future gas lift operations.

As gas is produced during the normal production mode, the accumulationof liquid in the annulus 372 may rise to a level higher than the liquidin the annulus 332. This is due to the closed position of the valve 336,which forces production fluids to flow through annulus 372.

When liquid in the annulus 372 has accumulated to a level high enough todisrupt or diminish normal gas production from the formation 309, theoperation of the well 308 may be changed to the “blow down” or liquidremoval mode. In the liquid removal mode, the second tubing string 320is lowered by the lifting device 392 into the extended position.Additionally, the valve 336 is positioned in an open position to allowfluid flow. Since the extended positioning of the second tubing string320 (i) seals the end cap 338 and (ii) allows pressurized gas from thesecond tubing string to enter the annulus 372, the pressurized gasinjected into the annulus 372 through the ports 364 is able to “lift”the liquid that has collected in the annulus 372 to the surface 313 ofthe well 308, where it is separated from the gas at the separator 314.The sealing engagement of the second tubing string 320 and the end cap338 isolates the pressurized lift gas from the annulus 332. At thesurface, the check valve 340 prevents pressurized gas that may exit theseparator from back flowing into the annulus 332.

Isolation of lift gas from annulus 332 may be particularly beneficialwhenever a gas lift operation is installed in the horizontal section ofa well. In such horizontal applications, lacking a positive gradetowards the vertical section of the well, injected lift gas can easilyflow opposite the desired direction. This undesired flow of lift gasinto the horizontal well will consume large quantities of lift gas andultimately cause the gas lift event to occur at a higher pressure. Thishigher pressure may exceed the reservoir pressure, thus allowing liftgas to flow into the reservoir producing formation. Additionally, thelift chamber that is created by the positive acting seal providesisolation greater than that available by using other sealing mechanisms,such as check valves. This positive acting seal also has clearadvantages in applications where solids in the liquid may prevent aneffective check valve seal.

When the well 308 is operated in the liquid removal mode, normalproduction of gas from the formation 309 is allowed to proceed throughthe annulus 332 and into the compressor 316. At the compressor 316, thegas may be pressurized for delivery to the production conduit 398. Aportion of the gas exiting the compressor 316 may also be diverted tocharge the second tubing string 320 for either the ongoing or future gaslift operations.

In another embodiment, valve 336 may be omitted, thus causing liquidlevels in annulus 33 and annulus 372 to rise in conjunction with oneanother. As such, when the well 308 is operated in the normal productionmode, production of gas from the formation 309 is allowed to flowthrough both the annulus 332 and annulus 373, then into the compressor316. Such a configuration might be particularly applicable in a verticalwell application where the gas lift mechanism is installed in a sump orrat-hole, below the producing horizon.

Referring to FIGS. 5-8, a downhole valve 506 is configured to be usedwith a gas lift system similar to the downhole valve 380 of FIGS. 2 and3. Downhole valve 506 also is associated with a first tubing string 510and a second tubing string 520. The second tubing string 520 ispositioned within the first tubing string 510 and, in contrast to thepreviously described axial movement, is configured to rotate between afirst position and a second position. Shoulders 524 positioned on anexternal surface of the second tubing string 520 engage stops 528positioned on an internal surface of the first tubing string 510 tolimit the rotational movement of the second tubing string 520 and todefine the first and second positions.

An aperture 532 is disposed in an end of the first tubing string 510similar to the aperture associated with first tubing string 310. Asealing member 536 such as, for example, one or more o-rings ispositioned within the aperture 532 to seal against the second tubingstring 520, which is received by the aperture 532. A first port 540, oralternatively a first plurality of ports, is provided in an end of thesecond tubing string 520 downhole of the aperture 532. The first port540 is in fluid communication with a first inner passage 544 of thesecond tubing string 520. A second port 550, or alternatively a secondplurality of ports, is positioned on the second tubing string 520 influid communication with the first inner passage 544 of the secondtubing string 520. The first and second ports 540, 550 are disposed onopposite sides of the aperture 532 and are both substantially open whenthe second tubing string 520 is positioned in the first position (seeFIG. 5). When the first and second ports 540, 550 are substantiallyopen, fluid communication is provided between the wellbore and anannulus 554 between the first tubing string 510 and the second tubingstring 520. This fluid communication allows production fluids to enterthe annulus 554 during a normal production mode of the well.

In the embodiment illustrated in FIG. 5, the second port 550 isconfigured to be substantially blocked when the second tubing string 520is in the second position. Alternatively, the first port 540 or both ofthe first and second ports 540, 550 may be substantially blocked whenthe second tubing string 520 is in the second position. When the firstand/or second ports 540, 550 are substantially blocked, fluidcommunication between the wellbore and the annulus 554 is substantiallyinhibited or prevented.

A third port 560, or alternatively a third plurality of ports, ispositioned on the second tubing string 520 in fluid communication with asecond inner passage 564 of the second tubing string 520. The third port560 is substantially blocked when the second tubing string 520 is in thefirst position, and the third port 560 is substantially open when thesecond tubing string 520 is in the second position. When the third port560 is substantially open, fluid communication is permitted between theannulus 554 and the second inner passage 564. This fluid communicationallows lift gas to remove downhole liquids during a blow down mode ofthe well.

Referring still to FIG. 5, but more specifically to FIGS. 7 and 8,sealing blocks 580 are positioned on or adjacent to an inner wall of thefirst tubing string 510 to substantially block the second and thirdports 550, 560 as described above. The sealing blocks 580 may be madefrom an elastomeric material such as a hard rubber or any other materialthat has suitable wear properties and is capable of providing a sealagainst ports on the second tubing string 520.

Referring more specifically to FIG. 5, the second inner passage 564 isfluidly separated from the first inner passage 544 by a barrier member570. Barrier member 570 may be a metal disk or any other suitablebarrier that is welded or otherwise secured or positioned within thesecond tubing string 520 to substantially inhibit or prevent fluidcommunication between the second inner passage 564 and the first innerpassage 544. In one embodiment, the second inner passage 564 is fluidlyconnected to a source of lift gas such that the lift gas may bedelivered through the second inner passage 564 to the annulus 554 tolift liquids in the annulus 554 to the surface of the well.Alternatively, the lift gas may be delivered through the annulus 554 tothe second inner passage 564 to lift and transport the liquids to thesurface through the second inner passage 564.

One primary difference between the downhole valve 380 and the downholevalve 510 is that the downhole valve 510 is operated by rotating thesecond tubing string 520 as opposed to imparting axial movement to thesecond tubing string. A rotator (not shown) may be positioned at orbeneath the wellhead of the well to rotate the second tubing string 520.The rotator would either manually or automatically rotate the tubing inorder to initiate or stop a gas lift event. A thrust bearing 584supports the weight of the second tubing string 320 against the firsttubing string 310, thus allowing rotational movement with less appliedtorque.

In another embodiment, the second tubing string is designed to form anisolated gas lift chamber without physically passing through an aperturein the first tubing string. In such a case, with the second tubingstring in a first position, production fluids could flow from the wellinto the tubing annulus between the first tubing string and the secondtubing string. The fluids may enter the tubing annulus through a portpositioned in a side wall of the first tubing string. Upon movement ofthe second tubing string to a second position, whether such movement isaxial or rotational, a seal would be formed thereby blocking flow ofproduction fluids into the tubing annulus, as well as blocking the flowof lift gas from the tubing annulus into the well.

Referring to FIGS. 9-12, a downhole valve 906 is configured to be usedwith a gas lift system similar to the use of downhole valves 380, 506 ofFIGS. 2 and 5. Downhole valve 906 is associated with a first tubingstring 910 and a second tubing string 920. In the embodiment illustratedin FIGS. 9 and 10, the second tubing string 920 is positioned within thefirst tubing string 910 and is configured to axially move between afirst position (see FIG. 9) and a second position (see FIG. 10).Cooperative shoulders and flanges (not shown) may be provided on thefirst and second tubing strings 910, 920 to limit the axial movement ofthe second tubing string 920 and to define the first and secondpositions.

A port 932, or a plurality of ports, or an aperture, is disposed in aside wall of the first tubing string 910 near a downhole end of thefirst tubing string 910. Alternatively, the port 932 may be positionedat any location along the first tubing string 910. The port 932 issimilar in function to the aperture 532 of FIG. 5 in that the port 932is capable of allowing fluid communication between the wellbore and anannulus 954 between the first and second tubing strings 910, 920. Suchfluid communication is permitted when the second tubing string 920 isplaced in the first position during a normal production mode of thewell. In contrast to the aperture 532, the port 932 does not receive orsurround the second tubing string 920 in either of the first and secondpositions.

A sealing member such as, for example, a plurality of sealing blocks 936are operatively positioned around the ports 932 to seal against thesecond tubing string 920 when the second tubing string 920 is in thesecond position. In the second position, the well is in a blow down modeand fluid communication through the ports 932 is substantially inhibitedor prevented. The sealing blocks 936 may be formed of an elastomer orany other material that is suitable for sealing against the secondtubing string 920.

A port 960, or alternatively a plurality of ports, is positioned on thesecond tubing string 920 in fluid communication with an inner passage964 of the second tubing string 920. A sleeve 966 is positioned withinthe first tubing string 910 and around a portion of the second tubingstring 920. The sleeve 966 may be made from an elastomeric material suchas a hard rubber or any other material that has suitable wear propertiesand is capable of providing a seal against port 960 on the second tubingstring 920. The sleeve 966 acts as a sealing member to substantiallyinhibit or prevent fluid communication through the port 960 when thesecond tubing string 920 is in the first position. During this normalproduction mode, fluid communication between the inner passage 964 andthe annulus 954 is substantially inhibited or prevented. When the secondtubing string 920 is axially moved into the second position, the sleeve966 no longer covers the port 960, and fluid communication is permittedthrough the open port 960. This fluid communication allows lift gas toremove downhole liquids during the blow down mode of the well. In oneembodiment, the inner passage 964 is fluidly connected to a source oflift gas such that the lift gas may be delivered through the innerpassage 964 to the annulus 954 to lift liquids in the annulus 954 to thesurface of the well. Alternatively, the lift gas may delivered throughthe annulus 954 to the inner passage 964 to lift and transport theliquids to the surface through the inner passage 964.

The downhole valve 906 selectively controls two fluid flow paths basedon axial movements of the second tubing string 920. In anotherembodiment, the downhole valve 906 could easily be adapted to providesimilar fluid control in response to rotational movement of the secondtubing string 920 similar to the rotational movement used to operatedownhole valve 506.

It should be appreciated by a person of ordinary skill in the art thatthe improved gas lift device may be used in horizontal or verticalportions of a wellbore, or alternatively in portions of a wellborehaving any particular angular orientation. The system may further beused in cased or uncased portions of the wellbore. The term tubing canmean production tubing, casing, liners, or conduits. Additionally, thegas-lift system is not limited to use with only gas-producing wells, butmay be used in any type of well, including wells for producing oil orany other type of gas, liquid, or other subterranean deposit. Similarly,the gas-lift system may be used to remove liquid from any type ofsubterranean or above-ground conduit or bore (i.e. not just wells) inwhich there is a desire to isolate a point of gas injection forliquid-removal purposes. Numerous control and automation processes maybe employed in conjunction with the gas-lift process described herein.

It should be apparent from the foregoing that an invention havingsignificant advantages has been provided. While the invention is shownin only a few of its forms, it is not just limited but is susceptible tovarious changes and modifications without departing from the spiritthereof.

1. A gas lift system for removing liquid from a wellbore, the systemcomprising: a first tubing string positioned within the wellbore; asecond tubing string disposed within the first tubing string, the secondtubing string movable between a first position and a second position, anannulus being present between the second tubing string and the firsttubing string; an aperture positioned in the first tubing string; asleeve slidingly disposed around a portion of the second tubing string;a port disposed in a wall of the second tubing string such that the portis substantially covered by the sleeve in the first position and issubstantially uncovered in the second position to permit fluidcommunication between an inner passage of the second tubing string andthe annulus; and a sealing member operatively associated with theaperture to allow fluid communication between the wellbore and theannulus when the second tubing string is in the first position, thesealing member substantially inhibiting fluid communication through theaperture when the second tubing string is in the second position.
 2. Thesystem of claim 1, wherein the aperture passes through an end cap in thefirst tubing string.
 3. The system of claim 1, wherein the aperture isdisposed in a side wall of the first tubing string.
 4. The system ofclaim 1, wherein the second tubing string is axially movable.
 5. Thesystem of claim 1, wherein the second tubing string is rotationallymovable.
 6. The system of claim 1, further comprising: a first flangedisposed on the second tubing string; a second flange disposed on thesecond tubing string; and wherein the sleeve is disposed around thesecond tubing string between the first flange and the second flangewithin the first tubing string.
 7. The system of claim 1, furthercomprising: a first flange disposed on the second tubing string; asecond flange disposed on the second tubing string; a shoulder disposedon an inner wall of the first tubing string and adapted to engage thesleeve when the second tubing string is in the second position; and aspring member operatively disposed on the second tubing spring betweenthe sleeve and the first flange.
 8. The system of claim 1, wherein thesleeve comprises a substantial cylindrical portion and extensionportions extending radially outward from an outer surface of the centralportion.
 9. The system of claim 1, wherein an end of the second tubingstring is sealed.
 10. The system of claim 1, wherein the sealing memberis one of an o-ring and a sealing block.
 11. The system of claim 7,wherein the spring member biases the sleeve toward the second flange inan uncompressed position.
 12. The system of claim 7, wherein the springmember is substantially compressed when the second tubing string is inthe second position.
 13. The system of claim 1, further comprising: alifting device connected to the second tubing string; a compressorhaving an inlet and an outlet, the outlet fluidly connected to thesecond tubing string; and a separator fluidly connected between theinlet of the compressor and the annulus.
 14. A gas lift system forremoving liquid from a wellbore, the system comprising: a first tubingpositioned within the wellbore, the first tubing string being fluidlyconnected to a separator; a second tubing string disposed within thefirst tubing string, the second tubing string being operativelyconnected to a lifting device to move the second tubing string between afirst position and a second position, the second tubing string having aninner passage fluidly connected to an outlet of a compressor; anaperture positioned near an end of the first tubing string, the aperturebeing adapted to receive an end of the second tubing string in thesecond position; a first flange disposed on the second tubing string; asecond flange disposed on the second tubing string; a sleeve slidinglydisposed around the second tubing string between the first flange andthe second flange within the first tubing string; an outlet disposed ina wall of the second tubing string such that the outlet is closed by thesleeve in the first position and is open in the second position topermit fluid communication between the inner passage of the secondtubing string and a first annulus between the first tubing string andthe second tubing string; and a sealing member for creating a sealbetween the aperture in the first tubing string and the end of thesecond tubing string in the second position.
 15. The system of claim 14,wherein a second annulus is present between the first tubing string andthe wellbore.
 16. The system of claim 15, wherein the second annulus isfluidly connected to an inlet of a compressor.
 17. The system of claim16, further comprising a valve fluidly connected between the secondannulus and the inlet of the compressor to selectively control fluidflow within the second annulus.
 18. The system of claim 14, wherein thelifting device is a hydraulic lifting device.
 19. A gas lift system forremoving liquid from a wellbore, the system comprising: a first tubingstring positioned within the wellbore; a second tubing string disposedwithin the first tubing string, the second tubing string rotatablebetween a first position and a second position; an aperture in the firsttubing string adapted to receive an end of the second tubing string inthe second position; a sealing member for creating a seal between theaperture in the first tubing string and the end of the second tubingstring in the second position; a first port positioned on the secondtubing string in fluid communication with a first inner passage of thesecond tubing string; a second port positioned on the second tubingstring in fluid communication with the first inner passage of the secondtubing string, the first and second ports being disposed on oppositesides of the sealed aperture, the first and second ports beingsubstantially open when the second tubing string is positioned in thefirst position, at least one of the first and second ports beingsubstantially blocked when the second tubing string is in the secondposition; a third port positioned on the second tubing string in fluidcommunication with a second inner passage of the second tubing string,the third port being substantially blocked when the second tubing stringis in the first position, the third port being substantially open whenthe second tubing string is in the second position.
 20. The system ofclaim 19, wherein the first inner passage is separated from the secondinner passage.
 21. The system of claim 19, wherein the second innerpassage is fluidly connected to a pressurized gas source.
 22. The systemof claim 19 further comprising: a first sealing block positioned on aninner wall of the first tubing string such that the first sealing blocksubstantially blocks the second port when the second tubing string is inthe second position; and a second sealing block positioned on an innerwall of the first tubing string such that the second sealing blocksubstantially blocks the third port when the second tubing string is inthe first position.
 23. A gas lift system for removing liquid from awellbore, the system comprising: a first tubing string positioned withinthe wellbore; a second tubing string disposed within the first tubingstring, the second tubing string having an inner passage and beingmovable between a first position and a second position, an annulus beingpresent between the second tubing string and the first tubing string; anaperture disposed in the first tubing string to permit fluidcommunication between the wellbore and the annulus when the secondtubing string is in the first position; and a port disposed in thesecond tubing string to permit fluid communication between the innerpassage and the annulus when the second tubing string is in the secondposition.
 24. The system of claim 23, wherein the aperture is disposedin an end cap of the first tubing string.
 25. The system of claim 23,wherein the aperture is disposed in a side wall of the first tubingstring.
 26. The system of claim 23, wherein the second tubing string isaxially movable.
 27. The system of claim 23, wherein the second tubingstring is rotationally movable.
 28. The system of claim 23, whereinfluid communication through the aperture is substantially inhibited whenthe second tubing string is in the second position.
 29. The system ofclaim 23, wherein fluid communication through the port is substantiallyinhibited when the second tubing string is in the first position.30.-40. (canceled)